The present invention relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an embodiment described herein, more particularly provides a multipart sliding joint for use with a floating rig.
Slip joints have been widely used for interconnecting a riser assembly to a floating rig. Floating rigs may be drill ships, semi-submersibles, floating drilling or production platforms, etc., and may be dynamically positioned, tethered, or otherwise maintained in position. A slip joint basically allows a riser assembly to alternately lengthen and shorten as a floating rig moves up and down (heaves) in response to wave action.
Recent developments in drilling and completion technology (such as managed pressure drilling) benefit from use of an internally pressurized riser assembly. Unfortunately, typical slip joints and methods of interconnecting riser assemblies to floating rigs are unsuited for use with pressurized riser assemblies, and/or are suited for use only in very benign environments, for example, environments with very limited rig heave.
In FIG. 1 a conventional riser assembly 10 and floating rig 12 are illustrated. A lower end of the riser assembly 10 is connected to a blowout preventer (BOP) stack 14, which is in turn connected to a wellhead 16 at the ocean floor or mudline. An upper end of the riser assembly 10 is connected via a slip joint 18, flow spool 20 and diverter 22 to a rig floor 24 typically having a rotary table 36 or top drive (not shown).
In this example, the slip joint 18 provides an attachment point for tensioner cables 26 which apply consistent tension to the riser assembly 10 as the rig 12 heaves. The slip joint 18 includes inner and outer telescoping sleeves or barrels 28, 30, with the tensioner cables 26 being attached to the outer barrel and the inner barrel being connected to the flow spool 20 and diverter 22. Thus, as the rig 12 heaves, the inner barrel 28 (which is connected to the rig floor 24 via the flow spool 20 and diverter 22) moves up and down relative to the outer barrel 30 (which is connected to the remainder of the riser assembly 10 therebelow).
Seals may be provided between the inner and outer barrels 28, 30, but in the past these seals have only been designed for containing relatively low pressures (such as 500 psi), in substantial part due to large manufacturing tolerances, requiring large seals with considerable wear allowance. In addition, the FIG. 1 example is unsuited for operations such as managed pressure drilling, in part because no rotating control device is provided to isolate the interior of the riser assembly 10 from the atmosphere at the surface. Instead, the diverter 22 and flow spool 20 vent the upper end of the riser assembly 10 to atmosphere, for example, via a mud tank 32, gas flare lines, etc.
Another reason the FIG. 1 example is unsuited for operations such as managed pressure drilling is that drilling mud returns are circulated via a choke 38, separator 40 and shale shaker 42 to the mud tank 32 without benefit of an annular seal (such as a rotating control device) to allow application of back pressure by the choke during circulation and drilling.
In FIG. 2 another example of a method of interconnecting the riser assembly 10 and floating rig 12 is illustrated. In this example, the BOP stack 14 is located at an upper end of the riser assembly 10, and the tensioner cables 26 are connected via a tensioner ring 44 and adapter 46 below the BOP stack.
Ball or flex joints 48 are interconnected between the slip joint 18 and the diverter 22, and between the slip joint and the BOP stack 14. Similar flex joints 48 may be used in the example of FIG. 1 above the slip joint 18.
It will be appreciated that, if the BOP stack 14 is to be maintained above water level 50, the available stroke of the slip joint 18 in the example of FIG. 2 has to be significantly reduced as compared to the example of FIG. 1. Thus, the FIG. 2 example is unsuited for use in environments in which substantial heave is encountered. In addition, the FIG. 2 example is unsuited for use with a pressurized riser assembly 10 since the diverter 22 vents the upper end of the riser assembly to atmosphere and no annular seal (such as a rotating control device) is provided.
With the BOP stack 14 positioned above water level 50, the BOP stack is of the type well known to those skilled in the art as a “surface” BOP stack. A surface BOP stack may include a single annular or ram blowout preventer, or a combination of annular and ram blowout preventers (such as a multiple cavity blowout preventer with dual annular blowout preventers on top), or a combination of multiple annular blowout preventers, or another blowout preventer configuration adopted for a particular drilling purpose.
In an attempt to alleviate the problem of reduced slip joint stroke and limited heave capability of the FIG. 2 example, the BOP stack 14 has been repositioned below water level 50 as illustrated in FIG. 3. However, this configuration introduces additional problems associated with access to the submerged BOP stack 14, extended length control and circulation lines, etc. In addition, the FIG. 3 example is still unsuited for use with a pressurized riser assembly 10.
In FIG. 4 an attempt to provide for a pressurized riser assembly 10 is illustrated. In this example, a rotating control device 52 is connected above the flow spool 20, and the flow spool is connected to the slip joint 18 via an adapter 54. A rotating control device is well known to those skilled in the art as providing a seal about a rotating tubular therein, thereby allowing maintenance of a pressure differential between the annulus above and below the seal while the tubular rotates within the device.
Importantly, the slip joint 18 is locked in its stroked closed (fully compressed) position, and so the slip joint provides no compensation at all for heave of the rig 12. Instead, the rig floor 24 displaces up and down relative to the upper end of the riser assembly 10 (at the rotating control device 52).
Relative lateral displacement between the upper end of the riser assembly 10 and the rig 12 is also permitted, with only the relatively flexible tensioner cables 26 and the intermittent presence of a drill pipe 56 passing through the rotary table 36 and into the rotating control device 52 being used to limit this lateral displacement. It will be appreciated that such lateral displacement is very undesirable (especially when the drill pipe 56 is not present) and significantly limits the allowable heave for the FIG. 4 example.
Therefore, it may be clearly seen that improvements are needed in the art of interconnecting floating rigs and riser assemblies.